Hydrocarbon drilling and production rigs often vent or flare gas. Operators and oil companies have increasingly become aware of the environmental impact of such flared gas with respect to CO2 emissions. There is also greater awareness of the economic benefit derived from the monitoring and reduction of emissions. Some countries have even implemented regulations requiring the measurement of flared gas. For these reasons, many operators have opted to measure the volume of flared gas.
Metering systems have been developed to measure flare gas primarily in industrial applications. Conventional systems have proven problematic. Metering system must function in extreme and variable conditions. The systems must be adaptable for large and small diameter pipe. The systems must be able to withstand high flow velocities (in excess of 100 m/s), changing gas composition, pressure differentials, contaminants, CO2, H2S and water.
Conventional metering systems include insertion turbines, thermal mass meters, annubars, and ultrasonic meters.
Turbine meters contain a rotor positioned in the flow path. The flow of gas causes rotation of the rotor. The gas flow rate is determined by the angular velocity of the rotor. The rotor contains bearings and rotor blades subject to wear by contaminants in the gas. Customary maximum flow range for turbine meters is 30 m/s.
Thermal mass meters normally include two temperature sensors. Situated in the gas flow, one sensor is heated to a predetermined temperature; the other sensing the temperature of the gas. Flow rate is calculated based on the temperature difference between the two sensors (higher flow rates cause increased cooling of the heated sensor). The flow range for thermal meters is 0.3 to 30 m/s.
Annubars detect differential pressures. The signal increases proportional to the square of the gas flow. Annubars are not effective for low flow applications because of the small pressure differentials.
Ultrasonic gas flow meters work on the time-of-flight measurement premise. The meters emit an ultrasonic signal. The transmission time of the signal is measured at increments along a diagonal path in both a downstream and upstream direction. The velocity of the gas causes the time for the signal traveling in the downstream direction to be shorter than the upstream direction. The gas flow rate is calculated from the time differential. The calculation depends on pressure, temperature and other factors. Ultrasound flow meters may require pockets in the pipe walls to contain the ultrasound meters. Contaminants tend to accumulate in the pockets and on the sensors and disrupt the system. Moreover, long sections of pipe can be required for the ultrasonic flowcell. Some ultrasonic systems pass the signal through the wall of the pipe, but the accuracy of these external systems is lessened when operating pressures and flow rates are low.
More recently, optical flow meters have been developed. U.S. Pat. No. 7,265,832 (incorporated herein by reference) describes an optical meter that measures flow velocity of small particles entrained with the gas flow. The system includes a light source, a first optical lens system that generates two beams of light and directs the beams through a first window in the pipe wall to form a pair of focus spots in the volume of pipe at the same location in the pipe cross-section but separated along an axis parallel to the flow direction. The particles entrained in the gas flow that travel along a trajectory coincident with the two focal points, scatter the light in succession and the time delay between scatter occurrences is inversely proportional to the particle velocity. A second window in the pipe wall is opposite the first window. Means collect a portion of the scattered light that pass through the second window. A second optical lens system directs the scattered light to one or more light detector means. An opaque obscuration is positioned to intercept beams at or behind the second window to prevent the unscattered light from reaching the detector. The first optical system, first window, second window, opaque obscuration and second optical system are centered on a common optical axis, perpendicular to the gas flow direction. The two beams of light are directed along the same common optical axis but the focus spots are separated laterally at the focal planes by approximately equal distance from the central axis. A pipe axis is parallel to the gas flow direction. A transverse axis is perpendicular to the optical axis and the pipe axis. Means reduce the beam convergence of the light entering the pipe, in the traverse axis, to widen the focal spots and present a larger scattering cross-section to gas particles traveling in the fluid stream. Means convert the detected light into electrical signals proportional to the incident light intensity. When scattered particles pass through each focal point, a pulse of light is scattered and received by respective detectors. The detectors generate an electrical pulse. Means determine the time delay between electrical pulses. The velocity of the particles is calculated when the distance between the focal points in known. Means determine the flow rate, which is proportional to the particle velocity.
In addition to metering flare gas, ultrasonic metering systems have been employed as part of a well bore and formation evaluation procedure. Critical information (e.g., permeability) may be learned about the formation from the fluids flowing from the formation to the well surface. Data about the amount of gas in the surface flow and the flow rate are used to evaluate the formation. U.S. Pat. No. 6,585,044 (incorporated herein by reference) describes a method and system for well bore and formation evaluation in under-balanced drilling that incorporates the use of an ultrasonic gas flow meter at the well surface.
Despite the advances made in gas flow measurement, the need still exists for an accurate, reliable and cost-efficient flare gas metering system and method adaptable to drilling and production rigs that are capable of generating data operators may use to evaluate formations during drilling and non-drilling applications and to monitor and control emissions for environmental and economic purposes.